Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel) or porous rock. Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing. The gas flowing up the production chamber is conveyed through an intake pipeline running from the wellhead to the suction inlet of a wellhead compressor. The compressed gas discharged from the compressor is then conveyed through another pipeline to a gas processing facility and sales facility as appropriate.
When natural gas is flowing up a well, formation liquids will tend to be entrained in the gas stream, in the form of small droplets. As long as the gas is flowing upward at or above a critical velocity (the value of which depends on various well-specific factors), the droplets will be lifted along with the gas to the wellhead. In this situation, the gas velocity provides the means for lifting the liquids, and the well is said to be producing by “velocity-induced flow”. Because liquids in the gas stream can cause internal damage to most gas compressors, a gas-liquid separator is provided in the intake pipeline to remove liquids from the gas stream before entering the compressor. The liquids may be pumped from the separator and reintroduced into the gas flow at a point downstream of the compressor, for eventual separation at the gas processing facility. Much more commonly, however, the liquids are collected in a tank on the well site.
In order to optimize total volumes and rates of gas recovery from a gas reservoir, the bottomhole flowing pressure should be kept as low as possible. The theoretically ideal case would be to have a negative bottomhole flowing pressure so as to facilitate 100% gas recovery from the reservoir, resulting in a final reservoir pressure of zero. In order to reduce the bottomhole pressure to a negative value, or to a very low positive value, it would be necessary to have a negative flowing pressure (i.e., less than atmospheric pressure) in the intake pipeline. This can be readily accomplished using well-known technology; i.e., by providing a wellhead compressor of sufficient power.
However, negative pressure in a natural gas pipeline would present an inherent problem, because any leak in the line (e.g., at pipeline joints) would allow the entry of air into the pipeline, because air would naturally flow to the area of lower pressure. This would create a risk of explosion should the air/gas mixture be exposed to a source of ignition. In addition to the explosion risk, entry of air into the pipeline also creates or increases the risk of corrosion inside the pipeline. For these reasons, the pressure in the intake pipeline is typically maintained at a positive level (i.e., higher than atmospheric). Therefore, in the event of a leak in the intake pipeline, gas in the pipeline will escape into the atmosphere, rather than air entering the pipeline. The explosion and corrosion risks are thus minimized or eliminated, but in a way that effectively limits ultimate recovery of gas reserves from the well.
One way of minimizing or eliminating the explosion and corrosion risks, while facilitating the use of negative pressures in the intake pipeline, would be to provide an oxygen sensor in association with the pipeline. The oxygen sensor would be adapted to detect the presence of oxygen inside the pipeline, and to shut down the compressor immediately upon detection of oxygen. This system thus would more safely facilitate the use of compressor suction to induce negative pressures in the intake pipeline and, therefore, to induce negative or low positive bottomhole flowing pressures. However, this system has an inherent drawback in that its effectiveness would rely on the proper functioning of the oxygen sensor. If the sensor malfunctions, and if the malfunction is not detected and remedied in timely fashion, the risk of explosion and/or corrosion will become manifest once again. This fact highlights an even more significant drawback in that this system would not prevent the influx of air into the pipeline in the first place, but is merely directed to mitigation in the event of that undesirable event.
For the foregoing reasons, there is a need for an improved method and apparatus for minimizing and protecting against the risk of explosion arising from the influx of air into a pipeline carrying a combustible gas such as natural gas under negative pressure. There is a particular need for such methods and apparatus that do not require or rely on the use of oxygen sensors or other instruments or devices that are prone to malfunction. Even more particularly, there is a need for such methods and apparatus that prevent the influx of air into the pipeline in the first place. The present invention is directed to these needs.